Mexico’s consumption of motor fuels is rising, its production of gasoline and diesel continues to fall, and U.S. refineries and midstream companies are racing to fill the widening gap. The export volumes are impressive: deliveries of finished motor gasoline from the U.S. to Mexico averaged 328 Mb/d in the third quarter of 2016, up 41% from the same period last year, and exports of low-sulfur diesel were up 29% to 194 Mb/d. And there’s good reason to believe that U.S.-to-Mexico volumes will keep growing. Today we look at recent trends in gasoline and diesel production and consumption south of the border, and at ongoing efforts to enable more U.S.-sourced gasoline and diesel to reach key Mexican markets by rail and pipeline.
On November 17, 2016, Tesoro Corp., the second-largest independent refiner in the Western U.S., announced an agreement to acquire Western Refining for an estimated $6.4 billion. This is the second acquisition that Tesoro has made this year, following the purchase of the MDU Resources/Calumet Specialty Products Partners’ joint venture refinery in North Dakota. And—ironically, considering the name of the company Tesoro is buying—the Western Refining deal will expand Tesoro’s footprint further east than ever. Today we evaluate the legacy assets of Tesoro and Western Refining and discuss how the two companies will likely fit together.
On the last day of October 2016, the first-ever shipment of Chinese motor gasoline to the U.S. was delivered to Buckeye’s Reading terminal in New York Harbor. The vessel took a circuitous route to New York, taking on cargo in the Hong Kong lightering zone, stopping in South Korea to take on another parcel of clean product, dropping off some benzene in Houston, and then finally heading to New York. That complicated journey suggests that the economics of a regular China-to-East Coast gasoline trade route are not there (at least for now), but the shipment highlights a trend: China is becoming more assertive as an exporter of petroleum products and the implications are global. In an international market defined by oversupply, inroads by China necessarily result in other producers losing market share. In today’s blog, we examine the impact of rising clean petroleum product exports—particularly from China, but also from India—and the corresponding ripple effects both on the world market and on U.S. refiners.
Over the past few weeks, publicly traded independent refining companies reported their latest quarterly results, and nearly all lamented on a common theme: the cost of Renewable Identification Numbers (RINs) is out of control. However, the financial burden is not felt equally across the industry, as companies with integrated marketing operations (refining, blending and retailing) don’t face the same RINs-cost albatross as merchant refiners who don’t have retail operations. Today we review the escalating RIN costs that obligated parties have endured this year and explain how the degree of financial pain depends on the level of refiners’ downstream integration.
Higher gasoline imports to the U.S. East Coast and weaker demand in the region have combined to bloat gasoline inventories, raising the question, what would it take to bring the market into balance? East Coast refinery output is down from this time last summer in response to somewhat lower crack spreads, but not enough to make a dent. Part of the problem is that while gasoline demand turned anemic in the Maine-to-Florida region, it is even weaker in many overseas markets. Also, the skill of East Coast blenders in dealing with a wide variety of supplies has always made the region an attractive destination for international product flows. Today, we continue our look at petroleum product cargo flows, and what they are telling us about the health of the market.
West Texas Intermediate (WTI) crude oil at Cushing is languishing back in the low $40s/bbl after a brief period of exuberance in the late spring. The blame for this latest oil-price retreat has shifted from high inventories of crude oil –– both on land and on tankers floating offshore –– to bloated petroleum-product inventories. There is some debate about how concerned the market should be about the increase in product stocks. In the opening episode of this blog series, we take a look at petroleum product cargo flows, and what they are telling us about the health of the market. We start today with middle distillates –– diesel and jet fuel.
Since 2012, the capacity of the Jones Act fleet of tankers and large articulated tug barges (ATBs) has increased by more than one-third, to 22.5 million barrels, and over the next 18 months, new-build tankers and more large ATBs will add another 4.5 million barrel –– or 20% –– to the capacity total. That’s raised a lot of concern among vessel owners about a capacity glut and the potential for bargain-basement charter rates. What’s important to factor in, though, is that a lot of older Jones Act vessels are getting close to retirement age, and their exit from the shipping “work force” will help to mitigate the effects of any over-build. Today, we continue our series on recent developments in the Jones Act fleet and how they affect crude oil and petroleum products shippers.
We are getting into the peak summer driving season and gasoline demand has been hitting all-time highs. You might think that inventories would be drawing down and that the U.S. would need to import more gasoline and gasoline blending components. But not so. U.S. refineries are cranking out the products. Gasoline stocks are up 10% from a year ago—15 million barrels (MMbbl) higher than the top of the five-year range—and last week gasoline inventories made a contra-seasonal move upward, increasing by 1.4 MMbbl. Net exports for the first quarter were up almost five times the same period in 2015. But what does all this mean for refined product markets in general, and gasoline balances in particular? Today, we examine the state of U.S. petroleum product markets.
A combination of pipelines and ships delivers some 4 MMb/d of transportation and heating fuels to the U.S. East Coast, most of it from Gulf Coast refineries. But there’s always room for improvement in refined products delivery infrastructure, whether it’s pipeline or port capacity expansions, new pipeline spurs, or new storage capability. The aim of these projects is almost always the same: to make distribution more efficient and to hold down the per-barrel cost of delivery. Today, we conclude our series with a look at possible infrastructure improvements and a note about the challenges these projects face.
Most of the gasoline, diesel, heating oil and jet fuel consumed in the U.S. East Coast region is piped in via long-distance pipelines from Gulf Coast refineries, but substantial amounts are moved in by ship—either from the Gulf Coast by Jones Act vessels or from overseas. These shipped-in volumes then need to make their way from port to consumer. Today we continue our examination of how transportation fuels and heating oil are delivered to East Coast users with a look at the ports and connecting pipelines that help move these critically important fuels.
The East Coast consumes more than 200 million gallons of gasoline, diesel, heating oil and jet fuel a day, but produces only one-fifth of that total, most of it at New Jersey and Pennsylvania refineries. To keep the region’s cars, trucks, trains and airplanes moving (and many of its homes and businesses heated) huge volumes of fuels need to be delivered from elsewhere, mostly via two pipelines from the Gulf Coast and the rest by ship—some from Gulf and other U.S. ports and some from overseas. Today, we continue our examination of the infrastructure that moves gasoline, diesel, heating oil and jet fuel to the nation’s largest fuel-consuming region with a look at four major pipelines.